1. Field of the Invention
This invention relates generally to oilfield wellbore systems for performing wellbore operations and more particularly to subsea downhole operations at an offshore location in which drilling fluid is continuously circulated through the wellbore and which utilizes a fluid return line that extends from subsea wellhead equipment to the surface for returning the wellbore fluid from the wellhead to the surface. Maintenance of the fluid pressure in the wellbore during drilling operations at predetermined pressures is key to enhancing the drilling operations.
2. Background of the Art
Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string. The drill string includes a drilling assembly (also referred to as the “bottom hole assembly” or “BHA”) that carries the drill bit. The BHA is conveyed into the wellbore by tubing. Continuous tubing such as coiled tubing or jointed tubing is utilized to convey the drilling assembly into the wellbore. The drilling assembly usually includes a drilling motor or a “mud motor” that rotates the drill bit. The drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters. A suitable drilling fluid (commonly referred to as the “mud”) is supplied or pumped under pressure from the surface down the tubing. The drilling fluid drives the mud motor and discharges at the bottom of the drill bit. The drilling fluid returns uphole via the annulus between the drill string and the wellbore inside and carries pieces of formation (commonly referred to as the “cuttings”) cut or produced by the drill bit in drilling the wellbore.
For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling) tubing is provided at the surface work station (located on a vessel or platform). One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore. Injectors may be placed at the sea surface and/or on the wellhead equipment at the sea bottom. In riser-type drilling, a riser, which is formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment and is utilized to guide the tubing to the wellhead. The riser also serves as a conduit for fluid returning from the wellhead to the sea surface. Alternatively, a return line, separate and spaced apart from the tubing, may be used to return the drilling fluid from the wellbore to the surface.
During drilling, the operators attempt to carefully control the fluid density at the surface so as to ensure an overburdened condition in the wellbore. In other words, the operator maintains the hydrostatic pressure of the drilling fluid in the wellbore above the formation or pore pressure to avoid well blow-out. The density of the drilling fluid and the fluid flow rate control largely determine the effectiveness of the drilling fluid to carry the cuttings to the surface. For such purpose, one important downhole parameter controlled is the equivalent circulating density (“ECD”) of the fluid at the wellbore bottom. The ECD at a given depth in the wellbore is a function of the density of the drilling fluid being supplied and the density of the returning fluid which includes the cuttings at that depth.
When drilling at offshore locations where the water depth is a significant fraction of the total depth of the wellbore, the absence of a formation overburden causes a reduction in the difference between pore fluid pressure in the formation and the pressure inside the wellbore due to the drilling mud. In addition, the drilling mud must have a density greater than that of seawater so then if the wellhead is open to seawater, the well will not flow. The combination of these two factors can prevent drilling to certain target depths when the full column of mud is applied to the annulus. The situation is worsened when liquid circulation losses are included, thereby increasing the solids concentration and creating an ECD of the return fluid even greater than the static mud weight.
In order to be able to drill a well of this type to a total wellbore depth at a subsea location, the bottom hole ECD must be reduced. One approach to do so is to use a mud filled riser to form a subsea fluid circulation system utilizing the tubing, BHA, the annulus between the tubing and the wellbore and the mud filled riser, and then inject gas (or some other low density liquid) in the primary drilling fluid (typically in the annulus adjacent the BHA) to reduce the density of fluid downstream (i.e., in the remainder of the fluid circulation system). This so-called “dual density” approach is often referred to as drilling with compressible fluids.
Another method for changing the density gradient in a deepwater return fluid path has been proposed, but not used in practical application. This approach proposes to use a tank, such as an elastic bag, at the sea floor for receiving return fluid from the wellbore annulus and holding it at the hydrostatic pressure of the water at the sea floor. Independent of the flow in the annulus, a separate return line connected to the sea floor storage tank and a subsea lifting pump delivers the return fluid to the surface. Although this technique (which is referred to as “dual gradient” drilling) would use a single fluid, it would also require a discontinuity in the hydraulic gradient line between the sea floor storage tank and the subsea lifting pump. This requires close monitoring and control of the pressure at the subsea storage tank, subsea hydrostatic water pressure, subsea lifting pump operation and the surface pump delivering drilling fluids under pressure into the tubing for flow downhole. The level of complexity of the required subsea instrumentation and controls as well as the difficulty of deployment of the system has delayed (if not altogether prevented) the practical application of the “dual gradient” system.